Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the oil to reach the surface. In order for oil to be "produced," that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock--e.g., sandstone, carbonates--which has pores of sufficient size, connectivity, and number to provide a conduit for the oil to move through the formation.
Hence, one of the most common reasons for a decline in oil production is "damage" to the formation that plugs the rock pores and therefore impedes the flow of oil. This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling fluid. Even after drilling, some drilling fluid remains in the region of the formation near the wellbore, which may dehydrate and form a coating on the wellbore. The natural effect of this coating is to decrease permeability to oil moving from the formation in the direction of the wellbore.
Another reason for lower-than-expected production is that the formation is naturally "tight" (low permeability formation), that is, the pores are sufficiently small that the oil migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability.
Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as "stimulation." Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., wellbore coating); (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating oil around or through the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. The present invention is directed primarily to the third of these processes.
Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation (i.e. above the minimum in situ rock stress). More particularly, a fluid is injected through a wellbore; the fluid exits the wellbore through holes (perforations in the well casing) and is directed against the face of the formation (sometimes wells are completed openhole where no casing and therefore no perforations exist, so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum in situ stress (also known as minimum principal stress) to initiate and/or extend a fracture(s) into the formation. Actually, what is created by this process is not always a single fracture, but a fracture zone, i.e., a zone having multiple fractures, or cracks in the formation, through which hydrocarbon can more easily flow to the wellbore.
Generally speaking, creating a fracture in a hydrocarbon-bearing formation requires a complex suite of materials. In the case of conventional fracturing treatments, four or five principal components are required: (1) a carrier fluid (usually water or brine), (2) a polymer, (3) a cross-linker, (4) a proppant, and (5) optionally a breaker. (Numerous other components are sometimes added, e.g. fluid loss agents, whose purpose is to control leak-off, or migration of the fluid into the fracture face.) Roughly, the purpose of these fluids is to first create/extend the fracture, then once it is opened sufficiently, to deliver proppant into the fracture, which keeps the fracture from closing once the pumping operation is completed. The carrier fluid is simply the means by which the proppant and breaker are carried into the formation. Thus, the fracturing fluid is typically prepared by blending a polymeric gelling agent with an aqueous solution (sometimes oil-based, sometimes a multi-phase fluid is desirable); often, the polymeric gelling agent is a solvatable polysaccharide, e.g., galactomannan gums, glycomannan gums, and cellulose derivatives. The purpose of the solvatable (or hydratable) polysaccharides is: (1) to provide viscosity to the fluid so that it can create/extend the fracture; and (2) to thicken the aqueous solution so that solid particles known as "proppant" (discussed below) can be suspended in the solution for delivery into the fracture. Again, the purpose of the proppant is to literally hold open or prop open the fracture after it has been created. Thus the polysaccharides function as viscosifiers, that is, they increase the viscosity of the aqueous solution by 10 to 100 times, or even more. In many fracturing treatments, a cross-linking agent is added which further increases the viscosity of the solution by cross-linking the polymer. The borate ion has been used extensively as a crosslinking agent for hydrated guar gums and other galactomannans to form aqueous gels, e.g., U.S. Pat. No. 3,059,909. Other suitable cross-linking agents include titanium (U.S. Pat. No. 3,888,312), chromium, iron, aluminum and zirconium (U.S. Pat. No. 3,301,723) compounds.
The purpose of the proppant is to keep the newly fractured formation in that fractured state, i.e., from re-closing after the fracturing process is completed; thus, it is designed to keep the fracture open--in other words to provide a permeable path (along the fracture) for the hydrocarbon to flow through the fracture and into the wellbore. More specifically, the proppant provides channels within the fracture through which the hydrocarbon can flow into the wellbore and therefore be withdrawn or "produced." Typical materials from which the proppant is made include sand (e.g. 20-40 mesh), bauxite, man-made intermediate-strength or high strength materials and glass beads. The proppant can also be coated with resin, which causes the resin particles to stick to one another, to help prevent proppant flowback in certain applications. Thus, the purpose of the fracturing fluid generally is two-fold: (1) to create or extend an existing fracture through high-pressure introduction into the geologic formation of interest; and (2) to simultaneously deliver the proppant into the fracture void space so that the proppant can create a permanent channel through which the hydrocarbon can flow to the wellbore.
One problem in fracturing operations is that the polymers often degrade before the operation is completed, as a result of thermal, oxidative/free radical, or acid hydrolysis reactions. This degradation causes the viscosity of the fracturing fluid to decrease correspondingly. Reduction in viscosity can reduce the fluid's effectiveness in creating fractures and delivering proppant to the desired sites. Two approaches have been used in an attempt to maintain the desired minimum viscosity in the fracturing fluid during the fracturing operation. One is to increase the initial loading of the polymer in the fluid, thus increasing the fluid's initial viscosity. However, this approach increases the energy required to pump the fluid into and through the wellbore. This and the cost of the additional polymer increases the overall cost of the fracturing operation, and also can lower well performance due to reduced conductivity in the proppant pack.
A second approach is to include a stabilizer in the fracturing fluid, to minimize polymer degradation. Commonly used stabilizers include methanol and sodium thiosulfate (Na.sub.2 S.sub.2 O.sub.3). Although the mechanism of action of these stabilizers is not fully understood, it is believed that they act as oxygen scavengers, and thus prevent polymer degradation that would otherwise be caused by oxygen dissolved in the fracturing fluid. However, methanol is flammable and therefore is generally avoided. A substantial quantity of sodium thiosulfate is required when it is used as a stabilizer. Neither of these two compounds is sufficiently effective as a stabilizer.
The problem of polymer degradation is becoming even more important recently because of the increasing incidence of very deep, hot (e.g., temperature &gt;250.degree. F.) wells. Therefore, there is a need for improved fracturing fluids that are suitable for use at high temperatures.